Proppant Treatments for Mitigating Erosion of Equipment in Subterranean Fracturing Operations

ABSTRACT

Systems and methods for treating proppant to mitigate erosion of equipment used in certain subterranean fracturing operations are provided. In some embodiments, the methods comprise: conveying a plurality of coated proppant particulates into a blender, wherein the coated proppant particulates comprise at least a partial coating of DFR and/or a hydratable polymer; blending the plurality of coated proppant particulates with an aqueous base fluid in the blender to form a treatment fluid; and introducing the treatment fluid from the blender into at least a portion of a subterranean formation.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of and claims priority to U.S. patentapplication Ser. No. 16/592,173 filed Oct. 3, 2019 and published as U.S.Patent Application Publication No. US 2020/0032136 A1, which is acontinuation-in-part of International Application No. PCT/US2018/016490filed Feb. 1, 2018, published as WO 2019/152042 A1, and both entitled“Proppant Treatments for Mitigating Erosion of Equipment in SubterraneanFracturing Operations,” each of which is incorporated by referenceherein in its entirety.

BACKGROUND

The present disclosure relates to systems and methods for performingfracturing treatments in certain subterranean formations.

Wells in hydrocarbon-bearing subterranean formations may be stimulatedto produce those hydrocarbons using hydraulic fracturing treatments. Inhydraulic fracturing treatments, a viscous fluid (e.g., fracturing fluidor pad fluid) is pumped into a subterranean formation at a sufficientlyhigh rate and/or pressure (e.g., above the fracture gradient of theformation) such that one or more fractures are created or enhanced inthe formation. These fractures provide conductive channels through whichfluids in the formation such as oil and gas may flow to a well bore forproduction. In order to maintain sufficient conductivity through thefracture, it is often desirable that the formation surfaces within thefracture or “fracture faces” be able to resist deformation and/orparticulate migration to prevent the fracture from narrowing or fullyclosing. Typically, proppant particulates suspended in a portion of thefracturing fluid are also deposited in the fractures when the fracturingfluid is converted to a thin fluid to be returned to the surface. Theseproppant particulates serve to prevent the fractures from fully closingso that conductive channels are formed through which producedhydrocarbons can flow.

In some conventional fracturing treatments, large amounts of water orother fluids (e.g., an average of 1 million gallons per fracturingstage) are pumped at high rates and pressures in order providesufficient energy downhole to form fractures in the formation of thedesired geometries. To create fractures in certain types of formations(e.g., unconventional formations or low permeability formations) or tocreate complex fracture network in subterranean formations, operatorsmay rely on the use of a low viscosity fluid (e.g., slickwater fluids)as the main fracturing fluid and small size proppant (e.g., 100-mesh) asthe proppant. Large amounts of proppant and fluid are often used inthese operations. Providing the large amounts of pumping power, water,proppants, and fluid additives (e.g., friction reducers) for theseoperations, and the disposal of water flowing back out of the formationafter these treatments, are often costly and time-consuming, and makefracturing operations economically impractical in many circumstances.

The pumps and other equipment used in pumping large volumes of lowviscosity fracturing fluids carrying large amounts of proppant at highinjection rates may make certain portions of that equipment susceptibleto damage in the form of erosion, corrosion, wear and tear, and fatigue.Ultimately, such damage can cause rupturing or blowout of fracturingfluid under high pressure as a result of cracking of certain portions ofthe surface equipment during a hydraulic fracturing treatment. Erosionmay decrease efficiencies or otherwise require the pump to be shut downmore frequently and repaired or replaced altogether.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating a treatment system according to certainembodiments of the present disclosure.

FIG. 2 is a diagram illustrating another treatment system according tocertain embodiments of the present disclosure.

FIG. 3A is a diagram illustrating another treatment system according toembodiments of the present disclosure.

FIG. 3B is a diagram illustrating another treatment system according toembodiments of the present disclosure.

FIG. 4 is a plot of percent friction reduction (% FR) as a function oftime (minutes) for the results of Example 1.

FIG. 5 is an illustration of the flat metal blade utilized in theblender of Example 2.

FIG. 6 is a graph illustrating data from erosion testing of certaintreatment fluids of Example 2, including treatment fluids according tocertain embodiments of the present disclosure.

FIG. 7 is a graph illustrating data from erosion testing of certaintreatment fluids of Example 2, including treatment fluids according tocertain embodiments of the present disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The present disclosure relates to systems and methods for performingfracturing treatments in certain subterranean formations. Moreparticularly, the present disclosure relates to systems and methods fortreating proppant to mitigate erosion of equipment used in certainsubterranean fracturing operations.

The present disclosure provides methods and systems for providing atleast a partial coating of a hydratable polymer and/or dry frictionreducer (DFR) on a plurality of proppant particulates used in fracturingoperations. As utilized herein, a “dry friction reducer” or “DFR” is achemical additive that alters fluid rheological properties to reducefriction created within the fluid as it flows. Such a DFR can be ahydratable polymer, and vice versa, in embodiments. In embodiments, thepartial coating comprises a hydratable polymer not typically considereda DFR and/or a DFR that is not a hydratable polymer.

In embodiments, the fracturing operations utilize slickwater fluids orother treatment fluids having a relatively low viscosity (e.g., lessthan or equal to about 25, 20, 15, 10, 9, 8, 7, 6, 5, 4, or 3 cP orbetween 3 and 25 cP, between 3 and 10 cP, or between 3 and 5 cP). In theembodiments of the present disclosure, the proppant particulates arecontacted with an aqueous liquid concentrate of a hydratable polymerand/or an amount of fresh water and a dry friction reducer (DFR),whereby the proppant particulates are at least partially coated with thehydratable polymer and/or the DFR at a job site (e.g., a well site)where the fracturing operation is performed, optionally while conveyingthose proppant particulates into a blender at the job site. Suchtechniques of coating particulates are sometimes referred to as“on-the-fly” coating. The proppant particulates coated in this mannerare blended with an aqueous base fluid to form a treatment fluid, andthe treatment fluid is then directly introduced into at least a portionof a subterranean formation and/or well bore.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods and systems of the present disclosure may reduce the degree towhich equipment at a well site through which fracturing fluids flow(including pumps, blenders, valves, conduits, connecting elbows, and thelike) may be eroded by the flow of proppant-carrying fluidstherethrough, particularly when such fluids are pumped at relativelyhigh rates. For example, the hydratable polymer and/or DFR may absorbwater once in contact with aqueous fluids, which may cause the coatingcomprising same to swell and/or expand in size and form a cushion orshock-absorbing coating on the proppant particulates. Thus, thehydratable polymer and/or DFR coating as described herein may make theproppant particulates less abrasive and/or may lessen the erosion impactof the proppant particulates on surfaces inside pumps or otherfracturing equipment. In some embodiments, the methods and systems ofthe present disclosure also may facilitate the self-suspension ofproppant in a treatment fluid, enhancing proppant suspension andtransport without the need for viscosifying agents or other additives inthe fluid itself. In some embodiments, the methods and systems of thepresent disclosure also may reduce friction and/or pumping horsepower inthe course of slickwater fracturing operations, in some instances, withlower concentrations of polymeric additives than conventionally-usedconcentrations of friction reducing agents. In some embodiments, themethods and systems of the present disclosure may provide one or more ofthese aforementioned benefits without adding significant cost orcomplexity to the operation, among other reasons, by using the alreadyexisting equipment at the well site.

Techniques of at least partially coating the proppant particulates whileconveying those proppant particulates into a blender at a job site(e.g., “on-the-fly”) can include, for example, processes in which onestream is continuously introduced into another stream so that thestreams are combined and mixed while continuing to flow as a singlestream as part of an on-going treatment at the job site. One suchon-the-fly coating method would involve conveying the dry proppantparticulates and the liquid concentrate of the hydratable polymer(and/or proppant particulates, DFR and an amount of water) into ablender, for example, via a vessel or conduit. Once inside the vessel orconduit, the proppant particulates would be contacted with the liquidconcentrate of the hydratable polymer (and/or with the amount of waterand the DFR) and coated with the hydratable polymer (and/or the DFR),after which the particulates move into a blender. In those embodiments,a device such as an auger, sand screw, or other similar device (or acombination of such devices) could be used both to aid in mixing theparticulates with the liquid concentrate (and/or with the amount ofwater and the DFR) and to convey the coated particulates into theblender. In other embodiments, the proppant particulates may be coated“on the fly” by spraying the liquid concentrate of the hydratablepolymer onto the dry proppant particulates (and/or by spraying freshwater onto a solids mixture comprising the proppant particulates and theDFR or spraying water onto the dry proppant particulates to providewetted proppant and subsequently contacting the wetted proppant with thedry DFR) as they move toward the blender (e.g., through a vessel orconduit, on a conveyer belt, or, for proppant particulates that arepoured or otherwise dispensed from a storage container into the blenderfrom above, falling into the blender unit via gravity). Such coatingmethods described in this paragraph are sometimes referred to as “drycoating” techniques. Batch or partial batch mixing also may be used toaccomplish such coating. In some embodiments, one or more of thesetechniques may be used in or near “real time” with the fracturingoperation in which the treatment fluid is formed in the blender isintroduced into a subterranean formation and/or well bore. Althoughdescribed as ‘spraying’, no particular spray pattern or sprayingapparatus is mandated, and ‘spraying’ can comprise spraying in a spraypattern or otherwise contacting.

As utilized herein, reference to a ‘DFR coating’ indicates that thefriction reducer (which can comprise a hydratable polymer or hydratablehydrogel) is added to the proppant particulates in a dry powder form(e.g., dry DFR is combined with dry proppant particulates to produce asolids mixture which is subsequently combined with an amount of water toproduce the coated proppant particulates and/or dry DFR is combined withwetted proppant particulates comprising proppant particulates that havebeen wetted with an amount of water to produce a wetted solids mixturethat is blended to provide the coated proppant particulates), whereasreference to a ‘hydratable polymer coating’ indicates that thehydratable polymer is added as a liquid concentrate to the proppantparticulates to produce the coated proppant particulates. Inembodiments, the amount of water comprises less than about 0.1, 0.2,0.3, 0.4, 0.5, 1, 2, or 3 wt %, or from about 0.1 to about 3, from about0.5 to about 3, or from about 1 to about 3 wt % of the coated proppant.

In some embodiments, the hydratable polymer and/or DFR coating may bedisposed on the proppant particulates only temporarily and/or for alimited period of time (e.g., for less than about 60 seconds, oralternatively, less than about 30 seconds, 20 seconds, or 15 seconds).Among other reasons, the hydratable polymer and/or DFR coating may bemade temporary in this way because the coating need only be present onthe proppant particulates while the treatment fluid carrying thoseparticulates passes through pumps, wellheads, and/or other equipment atthe well site that may be eroded by the flow of proppant particulatestherethrough. In at least some embodiments, the treatment fluidcomprising the coated proppant particulates is pumped into the well boreat a relatively high rate such that the time required for the fluid totravel from the blender tub to the well bore is a relatively shortperiod of time (e.g., less than about 30 seconds). Once the treatmentfluid comprising the coated proppant particulates is downstream of suchequipment, the hydratable polymer and/or DFR coating may no longer beuseful or needed for mitigating erosion of that equipment. Moreover, fora variety of reasons, it may be desirable for the hydratable polymerand/or DFR coating to be removed from the proppant particulates soonafter they enter the wellbore, allowing the hydratable polymer and/orDFR to disperse in the aqueous based fluid, thereby providing itsfriction reduction performance. In some embodiments, it may be desirablefor the hydratable polymer and/or DFR coating to be removed from theproppant particulates before those particulates penetrate one or morefractures in the subterranean formation. For example, in someembodiments, if the hydratable polymer and/or DFR coating on theproppant particulates were permanent, this coating could potentiallyhinder its complete removal from the proppant particulates as a resultof forming a tight proppant pack in the open space of fracture, and/ormay induce permeability damage therein. For at least these reasons, insome embodiments, the methods of the present disclosure may includeconveying the proppant particulates into the blender and/or introducedinto the formation without allowing the hydratable polymer and/or DFRcoating on the proppant particulates to stand and/or cure for asignificant period of time.

In some embodiments, the (DFR and/or hydratable polymer) coating thusmay become detached from the proppant particulates after the treatmentfluid carrying those particulates has passed through a pump, wellhead,and/or other equipment at the well site through which treatment fluidpasses before entering the well bore or formation. This may beaccomplished, among other ways, by the addition of a breaker, chelator,surfactant, or other additive that causes the coating to detach from theproppant particulates, or due to shear forces on the proppantparticulate in the treatment fluid. In these embodiments, the DFR and/orthe hydratable polymer of the coating may become dispersed in thetreatment fluid and, among other things, serve as a friction reducer forthe treatment fluid as it passes through tubing or conduits in the wellbore and/or the well bore itself.

The proppant particulates used in the methods and systems of the presentdisclosure may comprise any proppant particulate suitable for use in asubterranean fracturing operation. A particulate for use as a proppantparticulate may be selected based on the characteristics of size range,crush strength, and solid stability in the types of fluids that areencountered or used in wells. Examples of proppant particulate materialsthat may be suitable in certain embodiments include, without limitation,sand, gravel, bauxite, ceramic materials, glass materials, polymermaterials, wood, plant and vegetable matter, nut hulls, walnut hulls,cottonseed hulls, cured cement, fly ash, fibrous materials, compositeparticulates, hollow spheres or porous particulate. Mixtures ofdifferent kinds or sizes of proppant particulate can be used as well.

The proppant particulate may be selected to be an appropriate size toprop open the fracture and bridge the fracture width expected to becreated by the fracturing conditions and the fracturing fluid. Incertain embodiments, appropriate sizes of particulate for use as aproppant particulate may range from about 8 to about 600 U.S. StandardMesh. In certain embodiments, a proppant particulate may be sand-sized,which geologically is defined as having a largest dimension ranging fromabout 0.1 microns up to about 2 millimeters (mm). In certainembodiments, the proppant particulates may comprise particulates ofsmaller sizes, including microparticles, nanoparticles, or anycombinations thereof. According to certain embodiments of the presentdisclosure, the concentration of proppant particulate in the treatmentfluid may depend upon factors such as the nature of the subterraneanformation. In some embodiments, the concentration of proppantparticulate in the treatment fluid may be in the range of from about 0.1pounds of proppant per gallon of treatment fluid (lb/gal) to about 5lb/gal.

The hydratable polymer(s) and/or DFR(s) used in the methods and systemsof the present disclosure may comprise any linear (e.g., notcross-linked) polymer that may swell or otherwise hydrate in thepresence of an aqueous fluid and form a film or coating on a solidsurface. In certain embodiments, the hydratable polymer may be asynthetic polymer. Additionally, for example, the hydratable polymer maybe an anionic polymer or a cationic polymer, in accordance withembodiments of the present disclosure. By way of example, syntheticpolymers may comprise any of a variety of monomeric units, includingacrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid,N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinylformamide, itaconic acid, methacrylic acid, acrylic acid esters,methacrylic acid esters and combinations thereof.

In some embodiments, the hydratable polymer(s) and/or DFR(s) included inthe treatment fluid may have a molecular weight sufficient to provide adesired level of friction reduction once they become detached from thesurface of the proppant particulate. By way of example, the averagemolecular weight of suitable hydratable polymers and/or DFRs may be atleast about 2,500,000, as determined using intrinsic viscosities. Incertain embodiments, the average molecular weight of suitable hydratablepolymers and/or DFRs may be in the range of from about 7,500,000 toabout 20,000,000. Hydratable polymers and/or DFRs having molecularweights outside the listed range still may provide some degree offriction reduction.

One example of an anionic hydratable polymer that may be suitable incertain embodiments of the present disclosure is a polymer comprisingacrylamide and acrylic acid. The acrylamide and acrylic acid may bepresent in the polymer in any suitable concentration. An example of asuitable anionic hydratable polymer may comprise acrylamide in an amountin the range of from about 5% to about 95% and acrylic acid in an amountin the range of from about 5% to about 95%. Another example of asuitable anionic hydratable polymer may comprise acrylamide in an amountin the range of from about 60% to about 90% by weight and acrylic acidin an amount in the range of from about 10% to about 40% by weight.Another example of a suitable anionic hydratable polymer may compriseacrylamide in an amount in the range of from about 80% to about 90% byweight and acrylic acid in an amount in the range of from about 10% toabout 20% by weight. Yet another example of a suitable anionichydratable polymer may comprise acrylamide in an amount of about 85% byweight and acrylic acid in an amount of about 15% by weight. Aspreviously mentioned, one or more additional monomers may be included inthe anionic hydratable polymer comprising acrylamide and acrylic acid.By way of example, the additional monomer(s) may be present in theanionic friction reducing polymer in an amount up to about 20% by weightof the polymer.

Suitable hydratable polymers may be provided in an acid form or in asalt form. As will be appreciated, a variety of salts may be prepared,for example, by neutralizing the acid form of the acrylic acid monomeror the 2-acrylamido-2-methylpropane sulfonic acid monomer. In addition,the acid form of the polymer may be neutralized by ions present in thetreatment fluid. Indeed, as used herein, the term “polymer” is intendedto refer to the acid form of the hydratable polymer, as well as itsvarious salts. As will be appreciated, the hydratable polymer and/or DFRsuitable for use in the methods and systems of the present disclosuremay be prepared by any suitable technique. For example, the anionichydratable polymer comprising acrylamide and acrylic acid may beprepared through polymerization of acrylamide and acrylic acid orthrough hydrolysis of polyacrylamide (e.g., partially hydrolyzedpolyacrylamide). In some embodiments, the hydratable polymer may be asalt of a swellable polymer selected from the group consisting of saltsof carboxyalkyl starch, salts of carboxymethyl starch, salts ofcarboxymethyl cellulose, salts of crosslinked carboxyalkylpolysaccharide, derivatized cellulose, guar-based polymers, derivatizedguar polymers, synthetic polymers, biopolymers, or any combinationthereof.

In addition, the hydratable polymers suitable for use in embodiments ofthe present disclosure may be initially provided in any suitable formthat can be used to form an aqueous liquid concentrate. By way ofexample, the hydratable polymers may be provided in an aqueous solutionor may be provided in dry form and then combined with a small amount ofwater. As used herein, the term “aqueous liquid concentrate” refers to acomposition comprising the hydratable polymer in a more concentratedform than in the final treatment fluid that will be used in thesubterranean treatment. By way of example, the aqueous liquidconcentrate may comprise the hydratable polymer in an amount in therange of about 5% to about 100% by weight of the concentrate,alternatively, in an amount in the range of about 15% to about 60% byweight of the concentrate, and, alternatively, in an amount in the rangeof about 25% to about 45% by weight of concentrate. An example ofhydratable polymer dispersed in an aqueous continuous phase is providedby Halliburton Energy Services, Inc., under the name FR-76™ additive.One of ordinary skill in the art, with the benefit of this disclosure,will be able to select an appropriate form for the hydratable polymerfor a particular application based on a number of factors, includinghandling, ease of dissolution to a dilute polymer system, cost,performance and environmental factors, among others.

In embodiments, the DFR comprises a polymer. In embodiments, the DFRcomprises a synthetic polymer. In embodiments, the DFR comprises anionicor cationic polymer. In embodiments, the polymer includes a highmolecular weight polymer. In embodiments, the DFR comprisespolyacrylamide (PAM). In embodiments, the DFR comprises PAM, polyacrylicacid, hydrolyzed polyacrylamide, acrylamidomethylpropane sulfonate, or acombination thereof. In embodiments, the DFR comprises a polyacrylamide(PAM) copolymer. In embodiments, the DFR is a high viscosity dryfriction reducer (HVDFR) defined as a DFR that, when added to a fluidsuch as a particulate slurry (e.g., proppant-laden fracturing fluid),lowers the particle critical sedimentation velocity of the particulateslurry. In embodiments, the DFR is a fast acting friction reducer. Inembodiments, the DFR is a fast acting friction reducer which achievesits active function in a time interval of less than or equal to 60, 45,or 30 seconds. In embodiments, the DFR is a fast acting friction reducerwhich achieves at least 80 percent of its ultimate fluid frictionreduction effect in a time interval of less than or equal to 60, 45, or30 seconds. In embodiments, the DFR is a fast acting friction reducerwhich achieves at least 80 percent of its ultimate fluid viscosifyingeffect in a time interval of less than or equal to 60, 45, or 30seconds. In embodiments, the DFR is a solid material at ambienttemperature and pressure. In embodiments, the DFR is an associativeentity capable of forming extended structures in a fluid. Inembodiments, the DFR has a combination of the aforementioned features(e.g., is an associative entity capable of forming extended structuresin a fluid, a polymer, and comprises PAM). In embodiments, the DFRutilized to form the DFR coating comprises a dry hydratable hydrogel. Insuch embodiments, a DFR source (e.g., DFR source 356 detailedhereinbelow with reference to FIG. 3A and FIG. 3B) comprises a source ofthe dry hydratable hydrogel.

In some embodiments, the proppant particulates optionally may becontacted and/or coated with a functionalizing agent, such as a silanecoupling agent, among other purposes, to help the hydratable polymerattach or adhere to the surface of the proppant particulate. In someembodiments, the functionalizing agent may be applied as a liquidadditive to the surface of the dry proppant particulates “on-the-fly” asthe proppant particulates are being conveyed to a blender, using any ofthe aforementioned coating techniques discussed with regard to thehydratable polymer and/or DFR. For example, in some embodiments, aliquid solution or concentrate of the functionalizing agent may be mixedwith the proppant particulate using a device such as a sand screw orauger upstream of the location where the hydratable polymer and/or DFRis added and mixed using that same device. In some embodiments, thefunctionalizing agent may be used in an amount of about 0.05% to about0.2% (w/w) of the proppant particulates.

The aqueous base fluid used to form the treatment fluids used in themethods and systems of the present disclosure may comprise water fromany source. The term “base fluid” refers to the major component of thefluid (as opposed to components dissolved and/or suspended therein), anddoes not indicate any particular condition or property of that fluidssuch as its mass, amount, pH, etc. Aqueous fluids that may be suitableinclude fresh water, salt water (e.g., water containing one or moresalts dissolved therein), brine (e.g., saturated salt water), seawater,or any combination thereof. In certain embodiments of the presentdisclosure, the aqueous fluids comprise one or more ionic species, suchas those formed by salts dissolved in water. For example, seawaterand/or produced water may comprise a variety of divalent cationicspecies dissolved therein. In certain embodiments, the density of theaqueous fluid can be adjusted, among other purposes, to provideadditional particulate transport and suspension in the compositions ofthe present disclosure. In certain embodiments, the pH of the aqueousfluid may be adjusted (e.g., by a buffer or other pH adjusting agent) toa specific level, which may depend on, among other factors, the types ofviscosifying agents, acids, and other additives included in the fluid.One of ordinary skill in the art, with the benefit of this disclosure,will recognize when such density and/or pH adjustments are appropriate.Upon contacting with the aqueous base fluid, the at least partialcoating described herein can swell to form a swelled coating.

In certain embodiments, the treatment fluids used in the methods andsystems of the present disclosure optionally may comprise a breakeradditive, among other purposes, to degrade the hydratable polymer and/orfriction reducers in the fluid and/or facilitate removal of any filtercake left by the treatment fluid in the subterranean formation. Breakeradditives that may be suitable for use in certain embodiments of thepresent disclosure include, but are not limited to, oxidizers, enzymes,acids, acid-releasing materials, chelators, and any combinationsthereof. In some embodiments, the breaker additive may be encapsulatedor otherwise formulated to delay its reaction with other components inthe treatment fluid.

In certain embodiments, the treatment fluids used in the methods andsystems of the present disclosure optionally may comprise any number ofadditional additives. Examples of such additional additives include, butare not limited to, salts, surfactants, acids, diverting agents, fluidloss control additives, gas, nitrogen, carbon dioxide, surface modifyingagents, tackifying agents, foamers, corrosion inhibitors, scaleinhibitors, catalysts, clay control agents, biocides, friction reducers,antifoam agents, bridging agents, flocculants, H₂S scavengers, CO₂scavengers, oxygen scavengers, hydrate inhibitors, lubricants, weightingagents, relative permeability modifiers, resins, wetting agents, coatingenhancement agents, filter cake removal agents, antifreeze agents (e.g.,ethylene glycol), and the like. A person skilled in the art, with thebenefit of this disclosure, will recognize the types of additives thatmay be included in the fluids of the present disclosure for a particularapplication.

The treatment fluids of the present disclosure can be used in a varietyof subterranean treatment operations, including but not limited tofracturing operations. As used herein, the terms “treat,” “treatment,”“treating,” and grammatical equivalents thereof refer to anysubterranean operation that uses a fluid in conjunction with achieving adesired function and/or for a desired purpose. Use of these terms doesnot imply any particular action by the treatment fluid. In someembodiments, the fracturing operations of the present disclosure maycomprise injecting or otherwise introducing into a subterraneanformation and/or well bore a pad fluid that does not comprise asubstantial amount of proppant particulates (e.g., less than 0.01 poundsper gallon (ppg)) at a pressure sufficient to initiate, create, orenhance at least one fracture in the subterranean formation. In theseembodiments, the pad fluid may be followed by a treatment fluid thatcomprises proppant particulates that are at least partially coated witha hydratable polymer and/or DFR coating in accordance with the presentdisclosure. In certain embodiments, a treatment fluid that comprisesproppant particulates that are at least partially coated with ahydratable polymer and/or DFR coating in accordance with the presentdisclosure may be injected or otherwise introduced into the well boreand/or subterranean formation at a pressure sufficient to initiate,create, or enhance at least one fracture in the subterranean formation,with or without a preceding pad fluid. In some embodiments, thefracturing operations of the present disclosure may further compriseisolating and/or perforating an interval in the well bore correspondingto a portion of the subterranean formation where one or more fracturesare to be created and/or enhanced. Use of the term injecting should beinterpreted herein to mean “injecting via injection apparatus orotherwise introducing or adding.”

The amount (or concentration) of DFR or hydratable polymer to be coatedonto the proppant particulates can be based on a typical polymerconcentration designed to be added to the blender (e.g., blender140/240/340 detailed further hereinbelow) in forming the treatment fluid(e.g., friction reduction fracturing fluid).

An example of a system that may be used to prepare treatment fluids inaccordance with the present disclosure is illustrated in FIG. 1.Referring now to FIG. 1, system 100 includes a proppant source 110 fromwhich proppant particulates such as sand are supplied. In someembodiments, proppant source 110 may comprise a container, vehicle, orvessel containing proppant particulates, or may comprise a conduitthrough which proppant particulates may be dispensed. In the embodimentshown, a ramp or conveyer belt 115 may be positioned to facilitate themovement of proppant particulates out of the proppant source 110 andinto a hopper 120. The hopper 120 may comprise a funnel-shaped vesseland/or other equipment to facilitate the metering and/or transfer of thedesired quantities of proppant particulates into a blender 140. Proppantparticulates may be conveyed from the hopper 120 to the blender 140 viaa sand screw 130 having one end coupled to an outlet of the hopper 120and another end coupled to an inlet of the blender 140. As noted above,in other embodiments, sand screw 130 may be replaced with other devicessuch as augers, conveyer belts, or other devices suitable for conveyingproppant particulates and/or mixing them with a liquid substance (e.g.,the liquid concentrate of the hydratable polymer).

A liquid hydratable polymer source 150 (e.g., container, conduit orother such device) may be provided to dispense the liquid concentratecomprising the hydratable polymer into the sand screw 130 so that theliquid concentrate may be mixed with and contact the proppantparticulates as they move along the sand screw 130. The liquidhydratable polymer source 150 may be equipped with a liquid additivepump 155 to control the flow of the liquid concentrate into the sandscrew 130. In the embodiment shown the liquid additive pump 155 isdisposed adjacent to a point along the sand screw that is closer to thehopper 120 than it is to the blender 140. However, it is contemplatedthat the liquid concentrate may be dispensed into the sand screw (orother device used to convey the proppant particulate to the blender) atany point along its length. For example, in other embodiments, theliquid additive pump 155 is disposed adjacent to a point along the sandscrew that is closer to the blender 140 than it is to the hopper 120.

As shown, a breaker additive source 160 and an aqueous base fluid source170 are provided to dispense breaker additives or aqueous base fluids,respectively into the blender 140. As shown, those devices are also eachequipped with a liquid additive pump 165 or 175 to control the flow ofaqueous base fluid or breaker additives into the blender 140. Theblender 140 blends the aqueous base fluid, the breaker additive, and thecoated proppant particulates from sand screw 130 together to form atreatment fluid. Optionally, other additive sources (not shown) may beprovided that dispense additional additives into the blender 140 forblending into the treatment fluid. Once the treatment fluid is formed,its flow out of the blender 140 may be controlled via displacement pump145. The treatment fluid may flow into additional surface equipment 180,that may be used to pressurize or pump the treatment fluid into thewellhead 190 and into the formation (not shown) at the desired rate andpressure. Such equipment 180 may include any number of pumps, missileassemblies, fracturing manifolds, and the like, and the flow oftreatment fluid out of that equipment to wellhead 190 may be furthercontrolled by valve 185. As mentioned previously, the presence of thehydratable polymer coating on the surface of the proppant particulatesmay mitigate or prevent the erosion of internal surfaces in, forexample, blender 140, displacement pump 145, connecting elbows of pipes(not shown), and/or equipment 180 as the treatment fluid is blended andflows therein. Once the treatment fluids of the present disclosure haveflown through the wellhead 190 and into the formation (not shown), thehydratable polymer coated onto the proppant particulates may detach fromthe proppant particulates, among other reasons, to serve as a frictionreducing agent in the treatment fluid as it is pumped through casing,tubing, or other equipment in the well bore.

Referring now to FIG. 2, another example of a system that may be used toprepare treatment fluids in accordance with the present disclosure isillustrated. Referring now to FIG. 2, system 200 includes several of thesame components that were described with regard to the system shown inFIG. 1, including a proppant source 210, ramp or conveyer belt 215,hopper 220, sand screw 230, blender 240, displacement pump 245, breakeradditive source 260 (and associated liquid additive pump 265), aqueousbase fluid source 270 (and associated liquid additive pump 275),equipment 280, valve 285, and wellhead 290. Like system 100 in FIG. 1,system 200 also includes a liquid hydratable polymer source 250 (e.g.,container, conduit or other such device) equipped with a liquid additivepump 255 to dispense the liquid concentrate comprising the hydratablepolymer into the sand screw 230 so that the liquid concentrate may bemixed with and contact the proppant particulates as they move along thesand screw 230. System 200 also includes a functionalizing agent source257 (e.g., container, conduit or other such device) from which afunctionalizing agent such as an organosilane may be dispensed into thesand screw 230 so that the functionalizing agent may be mixed with andcontact the proppant particulates as they move along the sand screw 230.The functionalizing agent source 257 may be equipped with a liquidadditive pump 258 to control the flow of the functionalizing agent intothe sand screw 230. In the embodiment shown in FIG. 2, the liquidadditive pump 255 for dispensing the liquid concentrate of hydratablepolymer is disposed adjacent to a point along the sand screw 230 betweenthe valve 258 and the blender 140, in other words, downstream of liquidadditive pump 258 where the functionalizing agent is dispensed. Amongother benefits, this arrangement may allow for the functionalizing agentto contact the surface of the proppant particulates and treat thosesurfaces so that the hydratable polymer will more readily form a coatingon the proppant particulates. As a person of skill in the art willrecognize with the benefit of this disclosure, this relative arrangementof devices for applying the functionalizing agent and hydratable polymermay be used with devices or techniques for conveying the proppant to ablender other than a sand screw, including those referenced in the abovediscussion of “on-the-fly” coating techniques.

Referring now to FIG. 3A, another example of a system that may be usedto prepare treatment fluids in accordance with the present disclosure isillustrated. Referring now to FIG. 3A, system 300A includes several ofthe same components that were described with regard to the system shownin FIG. 1, including a proppant source 310 (e.g., a sand source), rampor conveyer belt 315, hopper 320 (e.g., a sand or proppant hopper),proppant (e.g., sand) screw 330, blender 340, displacement pump 345,breaker additive source 360 (and associated liquid additive pump 365),aqueous base fluid source 370 (and associated liquid additive pump 375),equipment 380, valve 385, and wellhead 390. System 300 also includes aDFR source 356 (e.g., container, conduit or other such device) fromwhich a dry (e.g., powdered) DFR may be dispensed into the hopper 320 sothat DFR may be mixed with and contact the proppant particulates (e.g.,sand) to form a solids mixture comprising the proppant (e.g., sand) andthe DFR. As depicted in FIG. 3A, ramp or conveyer belt 315 may bepositioned to facilitate the movement of DFR out of DFR source 356 andinto hopper 320, while proppant (e.g., sand) can be introduced intohopper 320 via inlet 311, which may provide for introduction of proppant(e.g., sand) into hopper 320 via, for example free fall (i.e., gravityfeed). Alternatively, a ramp or conveyor belt such as 315 can beutilized to introduce proppant (e.g., sand) into hopper 320 via proppantsource 310 and/or dry DFR can be introduced into hopper 320 via freefall from DFR source 356. System 300 also includes a freshwater source358 (e.g., container, conduit, tank, or other such device) which can beequipped with a liquid water pump and valve 359 to dispense fresh waterinto the proppant (e.g., sand) screw 330 so that the fresh water may bemixed with (e.g., sprayed on) and contact the solids mixture of theproppant particulates (e.g., sand) and DFR as they move along theproppant (e.g., sand) screw 330. In the embodiment shown in FIG. 3A, theliquid water pump 359 is configured for dispensing the water adjacent toa point along the proppant (e.g., sand) screw 330 adjacent hopper 320.Alternatively, water may be introduced elsewhere along proppant (e.g.,sand) screw 330, in embodiments.

Referring now to FIG. 3B, another example of a system that may be usedto prepare treatment fluids in accordance with the present disclosure isillustrated. Referring now to FIG. 3B, system 300B includes several ofthe same components that were described with regard to the system shownin FIG. 3A, including a proppant (e.g., sand) source 310, ramp orconveyer belt 315, hopper 320 (e.g., proppant or sand hopper), proppant(e.g., sand) screw 330, blender 340, displacement pump 345, breakeradditive source 360 (and associated liquid additive pump 365), aqueousbase fluid source 370 (and associated liquid additive pump 375),equipment 380, valve 385, and wellhead 390. System 300B also includes adry DFR source 356 (e.g., container, conduit or other such device) fromwhich a dry (e.g., powdered) DFR may be dispensed onto wetted proppanton sand screw 330 so that DFR may be mixed with and contact the proppantparticulates to form a wetted solids mixture comprising the proppant,the DFR, and an amount of water. In the embodiment of FIG. 3B, ramp orconveyor belt 315 can be utilized to introduce proppant (e.g., sand)from proppant (e.g., sand) source 310 into proppant (e.g., sand) hopper320. In this embodiment, fresh water from freshwater source 358 can bedispensed via fresh water pump and valve 359 onto proppant (e.g., sand)screw 330, whereby proppant (e.g., sand) is wetted to provide a wettedproppant (e.g., wetted sand). DFR source 356 can be configured such thatDFR can be introduced onto proppant (e.g., sand) screw 330 downstreamfrom water addition from water source 358, whereby the wetted proppant(e.g., wetted sand) can be contacted with DFR from DFR source 356 toprovide coated proppant (e.g., coated sand) that is introduced intoblender 340. Such relative arrangement of devices for applying the waterand DFR, as described with reference to FIGS. 3A and 3B, may be usedwith devices or techniques for conveying the proppant (e.g., sand) to ablender other than a proppant (e.g., sand) screw, including thosereferenced in the above discussion of “on-the-fly” coating techniques.Proppant (e.g., sand) coated with DFR as described herein is placed inblender tub 340 and combined with an aqueous based fluid (e.g., water)from source 370 controlled by valve 375 and blended to form a proppantladen fluid (e.g., a fracturing fluid), which may be conveyed to pumpingequipment 380 and further pumped into a well via wellhead 390, forexample to perform a hydraulic fracturing operation on a subterraneanformation penetrated by the wellbore. Flow from the blender 340 to thewellhead 390 may be controlled by one or more valves 345 and 385. It isnoted that the system of FIG. 3B for applying wetted proppant with DFRcan be operated substantially the same as described hereinabove withregard to FIG. 2, in embodiments, but with “DFR in place of “liquidhydratable polymer”, and “fresh water” in place of “functionalizingagent”.

In embodiments, a method of mitigating erosion of fracturing equipmentduring a fracturing treatment comprises: forming a plurality of coatedproppant particulates having at least a partial coating of a dryfriction reducer (DFR) and/or a hydratable polymer on a proppant;blending the plurality of coated proppant particulates with an aqueousbase fluid in the blender to form a treatment fluid, whereby the atleast the partial coating hydrates and swells to form a swelled coatingwhich mitigates a striking impact of the proppant on downstreamfracturing equipment; injecting the treatment fluid downhole via thefracturing equipment whereby the proppant is placed in fractures createdby the injection of a fracturing fluid.

In embodiments, a method of mitigating erosion of fracturing equipmentduring a fracturing treatment comprises: adding a solids-free fracturingfluid into the wellbore at an injection rate for generating a treatingpressure above a fracture gradient to create one or more fractures inthe subterranean formation; adding, via fracturing equipment, atreatment fluid into the wellbore to place proppant into the one or morefractures, wherein the treatment fluid is prepared as described herein.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of certain embodiments are given.The following examples are not the only examples that could be givenaccording to the present disclosure and are not intended to limit thescope of the disclosure or claims.

EXAMPLES Example 1: Friction Reduction Performance

A friction flow loop was used to compare the friction reductionperformance of slickwater that was prepared with a known concentrationof dry FR polymer coated on sand to a control slickwater in which thissame FR polymer concentration was dispersed in tap water. For thecontrol slickwater, a 10 L volume of slickwater was prepared by mixing3.6 g of dry FR in 10 L of tap water to prepare a slickwater with a dryFR concentration of 3 lbm/Mgal. For the slickwater prepared with dryFR-coated sand, 600 g of 100-mesh sand was first dry mixed with 3.6 g ofdry FR to provide a 3-ppg sand concentration in 10 L of water. A volumeof 24 mL of fresh water was then slowly dribbled into the sand/dry FRmixture while mixing to dampen the content and anchor the dry FR ontosand surfaces. This sand/FR mixture was then poured into the containercontaining 10 L of tap water, while the water was being stirred at 400rpm. The stirring was continued for approximately 2 min using a handhelddrill. After this stirring period, sand was allowed to settle to thebottom of the container, and the slickwater was separated for use in theflow loop testing to determine friction reduction performance.

As seen in FIG. 4, the friction reduction performance of the materialwas not degraded using the method. The control and coated methods bothexhibited a percent FR reduction (% FR) of approximately 72% at about1.75 minutes.

Example 2: Erosion Testing

Three Control samples of treatment fluids were prepared and tested asfollows. For Control #1, 24 grams of 100-mesh sand was added to a 1-LWaring blender containing 200 mL of deionized (DI) water (i.e., 1 ppgconcentration of sand). For Control #2, 24 grams of 100-mesh sand wasadded to a 1-L Waring blender containing 200 mL of deionized (DI) water(i.e., 1 ppg concentration of sand), and 0.2 mL of FR76™ additive, ananionic hydratable polymer additive provided by Halliburton EnergyServices, Inc., was added (i.e., 1 gal/Mgal concentration of the FR76™additive). For Control #3, 24 grams of 100-mesh sand was added to a 1-LWaring blender containing 200 mL of deionized (DI) water (i.e., 1 ppgconcentration of sand), and 0.4 mL of FR-76™ additive was added. Test #1sample was prepared by dry coating 0.2 mL of FR76™ additive onto 24grams of 100-mesh sand, and the coated sand was added to a 1-L Waringblender containing 200 mL of DI water. Test #2 sample was prepared bydry coating 0.4 mL of FR76™ additive onto 24 grams of 100-mesh sand, andthe coated sand was added to a 1-L Waring blender containing 200 mL ofDI water. Table 1 shows the compositions of Control #1, Control #2, andControl #3.

TABLE 1 Sample Components Control #1 24 g of 100-mesh sand in 200 mL DIwater Control #2 24 g of 100-mesh sand and 0.2 mL FR-76 ™ in 200 mL DIwater Control #3 24 g of 100-mesh sand and 0.4 mL FR-76 ™ in 200 mL DIwater   Test #1 24 g of 100-mesh sand dry coated with 0.2 mL FR-76 ™,added to 200 mL DI water   Test #2 24 g of 100-mesh sand dry coated with0.4 mL FR-76 ™, added to 200 mL DI water Comparative 24g of 100-meshsand dry coated with 1% SandWedge ® NT, added to 200 mL DI water

Each of Control #1, Control #2, and Control #3 was blended in the Waringblender for 45 minutes at 3,000 rpm using a flat metal blade of a knownmass. FIG. 5 depicts such a flat blade. Each blade was weighed beforeand after blending to determine its decrease in mass during the blendingprocess. The amounts of the decreases in the mass of each blade afterblending each sample are shown in FIG. 6. As demonstrated by this data,while the presence of the hydratable polymer dispersed in the fluidreduced the erosion of the blender blade to some degree, dry coating thesame amount of the hydratable polymer onto the sand, as per thisdisclosure, reduced the erosion of the blender blade even further.

Additional samples of treatment fluids, including Test #1 and Test #2shown in Table 1, were prepared by separately adding the componentslisted in Table 1 to 1 L Waring blenders. Test #1 comprised 24 g of100-mesh sand dry coated with 0.2 mL FR-76™, added to 200 mL DI water,while Test #2 comprised 24 g of 100-mesh sand dry coated with 0.4 mLFR-76™, added to 200 mL DI water. A comparative sample (‘Comparative’ inFIG. 7 and Table 1) comprising SANDWEDGE® NT is a polymeric resinavailable from Halliburton Energy Services, Inc.

Each of the samples above was blended in the Waring blender for 20, 60,and 180 second at 3,000 rpm using a flat metal blade of a known mass.(The Control #1 sample was run twice, and labeled Control 1 Run 1 andControl 1 Run 2 in FIG. 7.) Each blade was weighed before and afterblending to determine its decrease in mass during the blending process.The amounts of the decreases in the mass of each blade after blendingeach sample are shown in FIG. 7. As demonstrated by this data, while thepresence of the hydratable polymer dispersed in the fluid reduced theerosion of the blender blade to some degree, dry coating the hydratablepolymer onto the sand as per this disclosure reduced the erosion of theblender blade even further, even using smaller amounts of the hydratablepolymer. This data also demonstrates that at least the polymeric coatingof SandWedge® NT tested in this example did not reduce erosion of theblade to the extent accomplished by the hydratable polymer coatings ofthe present disclosure.

ADDITIONAL DISCLOSURE

The following are non-limiting, specific embodiments in accordance withthe present disclosure:

Embodiment A: A method comprising: conveying a plurality of proppantparticulates into a blender; contacting a plurality of proppantparticulates with an aqueous liquid concentrate comprising a hydratablepolymer to at least partially coat one or more of the proppantparticulates with the hydratable polymer, thereby forming coatedproppant particulates; blending the plurality of proppant particulatescomprising the coated proppant particulates with an aqueous base fluidin the blender to form a treatment fluid, the treatment fluid having aviscosity of about 25 cP or less; and introducing the treatment fluidfrom the blender into at least a portion of a subterranean formation.

Embodiment B: A method comprising: introducing an aqueous fracturingfluid into a well bore penetrating at least a portion of a subterraneanformation at or above a pressure sufficient to create or enhance atleast one fracture in the subterranean formation, the aqueous fracturingfluid having a viscosity of about 25 cP or less; conveying a pluralityof proppant particulates from a storage container into a blender at ajob site where the well bore is located; contacting the plurality ofproppant particulates with an aqueous liquid concentrate comprising ahydratable polymer to at least partially coat a portion of the proppantparticulates with the hydratable polymer; blending the plurality ofproppant particulates comprising the coated proppant particulates withan aqueous base fluid in the blender to form a treatment fluid, thetreatment fluid having a viscosity of about 25 cP or less; andintroducing the treatment fluid from the blender into the well bore.

Embodiment C: A method comprising: introducing an aqueous fracturingfluid into a well bore penetrating at least a portion of a subterraneanformation at or above a pressure sufficient to create or enhance atleast one fracture in the subterranean formation, the aqueous fracturingfluid having a viscosity of about 25 cP or less; using an auger, a sandscrew, or a combination thereof to convey a plurality of proppantparticulates from a storage container into a blender at a job site wherethe well bore is located; contacting the plurality of proppantparticulates with a functionalizing agent, and contacting the pluralityof proppant particulates with an aqueous liquid concentrate comprising ahydratable polymer to at least partially coat a portion of the proppantparticulates with the hydratable polymer, thereby forming coatedproppant particulates; blending the plurality of proppant particulatescomprising the coated proppant particulates with an aqueous base fluidin the blender to form a treatment fluid, the treatment fluid having aviscosity of about 25 cP or less; and introducing the treatment fluidfrom the blender into the well bore.

Embodiment D: A method comprising: conveying a plurality of coatedproppant particulates into a blender, wherein the coated proppantparticulates comprise at least a partial coating of dry friction reducer(DFR) and/or a hydratable polymer; blending the plurality of coatedproppant particulates with an aqueous base fluid in the blender to forma treatment fluid; and introducing the treatment fluid from the blenderinto at least a portion of a subterranean formation.

Embodiment E: The method of Embodiment D further comprising forming thecoated proppant particulates by: contacting a plurality of proppantparticulates with an aqueous liquid concentrate comprising a hydratablepolymer to at least partially coat one or more of the plurality ofproppant particulates with the hydratable polymer.

Embodiment F: The method of Embodiment E wherein forming the coatedproppant particulates further comprises: mixing the DFR with a pluralityof particulates of the proppant to form a solids mixture and combiningthe solids mixture with an amount of water to form the coated proppantparticulates comprising the at least the partial coating of the DFR; orwetting a plurality of particulates of the proppant with an amount ofwater to form a wetted proppant and combining the wetted proppant withthe DFR to form the coated proppant particulates comprising the at leastthe partial coating of the DFR.

Embodiment G: The method of Embodiment E or Embodiment F furthercomprising: while conveying the plurality of coated proppantparticulates into the blender, contacting the plurality of proppantparticulates with a functionalizing agent before contacting theplurality of proppant particulates with the aqueous liquid concentratecomprising the hydratable polymer.

Embodiment H: The method of Embodiment G, wherein the functionalizingagent comprises an organosilane.

Embodiment I: The method of Embodiment E or Embodiment F, whereincontacting the plurality of proppant particulates with the aqueousliquid concentrate comprises spraying the aqueous liquid concentrateinto the plurality of proppant particulates as the proppant particulatesare dispensed from a storage container.

Embodiment J: The method of any of Embodiment A through Embodiment I:wherein the subterranean formation includes at least one fracture.

Embodiment K: The method of any of Embodiment A through Embodiment J,wherein the treatment fluid is introduced into at least a portion of thesubterranean formation using one or more pumps.

Embodiment L: The method of any of Embodiment A through Embodiment Kfurther comprising, after introducing the treatment fluid into at leasta portion of the subterranean formation: allowing at least a portion ofthe hydratable polymer and/or DFR of the coated proppant particulates todetach from the proppant particulates and disperse into the treatmentfluid.

Embodiment M: The method of any of Embodiment A through Embodiment Lfurther comprising depositing at least a portion of the plurality ofproppant particulates in at least one fracture of the subterraneanformation.

Embodiment N: The method of any of Embodiment A through Embodiment M,wherein the viscosity of the treatment fluid is less than about 25, 20,15, 10, 9, 8, 7, 6, 5, 4, or 3 cP, or in a range of from about 3 cP toabout 20 cP, from about 3 cP to about 10 cP, or from about 3 cP to about5 cP.

Embodiment O: The method of any of Embodiment A through Embodiment N,wherein the plurality of coated proppant particulates are conveyed intothe blender using an auger, a sand screw, or both.

Embodiment P: The method of any of Embodiment A through Embodiment 0further comprising blending a breaker additive with the aqueous basefluid and the plurality of coated proppant particulates in the blenderto form the treatment fluid.

Embodiment Q: The method of any of Embodiment A through Embodiment P,wherein the hydratable polymer and/or the DFR comprises at least twomonomeric units selected from the group consisting of: acrylamide,acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid,N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinylformamide, itaconic acid, methacrylic acid, an acrylic acid ester, amethacrylic acid ester, guar-based polymers, synthetic polymers,biopolymers, and any combination thereof.

Embodiment R: A method comprising: introducing an aqueous fracturingfluid into a well bore penetrating at least a portion of a subterraneanformation at or above a pressure sufficient to create or enhance atleast one fracture in the subterranean formation, the aqueous fracturingfluid having a viscosity of about 25 cP or less; conveying a pluralityof proppant particulates from a storage container into a blender;contacting the plurality of proppant particulates with DFR and/or withan aqueous liquid concentrate comprising a hydratable polymer to atleast partially coat a portion of the proppant particulates with the DFRand/or with the hydratable polymer, thereby forming coated proppantparticulates; blending the plurality of proppant particulates comprisingthe coated proppant particulates with an aqueous base fluid in theblender to form a treatment fluid; and introducing the treatment fluidfrom the blender into the well bore.

Embodiment S: The method of Embodiment R further comprising, afterintroducing the treatment fluid into the well bore: allowing at least aportion of the DFR and/or the hydratable polymer of the coated proppantparticulates to detach from the proppant particulates and disperse intothe treatment fluid.

Embodiment T: The method of Embodiment R or Embodiment S furthercomprising depositing at least a portion of the plurality of proppantparticulates in at least one fracture in the subterranean formation.

Embodiment U: The method of any of Embodiment R through Embodiment T,wherein the plurality of proppant particulate are conveyed into theblender using an auger, a sand screw, or both.

Embodiment V: The method of any of Embodiment R through Embodiment U,wherein the treatment fluid has a viscosity of about 25 cP or less.

Embodiment W: The method of any previous Embodiment further comprisingdepositing at least a portion of the plurality of proppant particulatesin the at least one fracture.

Embodiment X: The method of any previous Embodiment further comprisingblending a breaker additive with the aqueous base fluid and theplurality of proppant particulates (e.g., coated proppant particulates)in the blender to form the treatment fluid.

Embodiment Y: A method of mitigating erosion of fracturing equipmentduring a fracturing treatment, the method comprising: forming aplurality of coated proppant particulates having at least a partialcoating of a dry friction reducer (DFR) and/or a hydratable polymer on aproppant; blending the plurality of coated proppant particulates with anaqueous base fluid in the blender to form a treatment fluid, whereby theat least the partial coating hydrates and swells to form a swelledcoating which mitigates a striking impact of the proppant on downstreamfracturing equipment; injecting the treatment fluid downhole via thefracturing equipment whereby the proppant is placed in fractures createdby the injection of a fracturing fluid.

Embodiment Z1: The method of Embodiment Y, wherein forming the pluralityof coated proppant particulates further comprises: combining the DFRwith a plurality of particulates of the proppant to form a solidsmixture and mixing the solids mixture with an amount of water to formthe coated proppant particulates comprising the at least the partialcoating of the DFR on the proppant.

Embodiment Z2: The method of Embodiment Z1, wherein mixing the solidsmixture with the amount of water comprises combining the solids mixturewith the amount of water to provide a wetted solids mixture and passingthe wetted solids mixture through an auger.

Embodiment Z3: The method of Embodiment Y, wherein forming the pluralityof coated proppant particulates further comprises: contacting aplurality of particulates of the proppant with an aqueous liquidconcentrate comprising a hydratable polymer to at least partially coatone or more of the plurality of particulates of the proppant with thehydratable polymer, thereby forming the coated proppant particulates.

Embodiment Z4: The method of Embodiment Y, wherein forming the pluralityof coated proppant particulates further comprises wetting the pluralityof particulates of the proppant with an amount of water to form a wettedproppant and mixing the wetted proppant with the DFR to form the coatedproppant particulates comprising the at least the partial coating of theDFR on the proppant.

Embodiment Z5: The method of Embodiment Z4, wherein mixing the wettedproppant with the DFR comprises combining the wetted proppant with theDFR to provide a wetted solids mixture and passing the wetted solidsmixture through an auger.

Embodiment Z6: The method of any of Embodiment Z1, Z2, Z4, or Z5,wherein the amount of water comprises less than about 0.1, 0.2, 0.3,0.4, 0.5, 1, 2, or 3 wt % of the coated proppant particulates.

Embodiment Z7: A method of mitigating erosion of fracturing equipmentduring a fracturing treatment, the method comprising: adding asolids-free fracturing fluid into the wellbore at an injection rate forgenerating a treating pressure above a fracture gradient to create oneor more fractures in the subterranean formation; adding, via fracturingequipment, a treatment fluid into the wellbore to place the proppantinto the one or more fractures, wherein the treatment fluid is preparedby: forming a coated proppant by: (i) combining a plurality ofparticulates of the proppant with a dry friction reducer (DFR) and anamount of water to at least partially coat one or more of the pluralityof particulates of the proppant with the DFR, or (ii) contacting aplurality of particulates of the proppant with an aqueous liquidconcentrate comprising a hydratable polymer to at least partially coatone or more of the plurality of proppant particulates with thehydratable polymer; blending the coated proppant with an aqueous-basedfluid to form the treatment fluid for adding into the wellbore, wherebythe coated proppant hydrates with water, thus swelling to provide aswelled coating that mitigates a striking impact of the proppant on thefracturing equipment during the adding, via the fracturing equipment, ofthe treatment into the wellbore to place the proppant into the one ormore fractures.

Embodiment Z8: The method of Embodiment Z7 comprising (i), whereinforming the coated proppant comprises passing the proppant, the DFR, andthe amount of water through an auger.

Embodiment Z9: The method of Embodiment Z8, wherein the amount of watercomprises less than about 0.1, 0.2, 0.3, 0.4, 0.5, 1, 2, or 3 wt % ofthe coated proppant.

Embodiment Z10: A system for mitigating erosion of fracturing equipmentduring a fracturing treatment, the system comprising: a proppant hopperconfigured for holding a proppant, a wetted proppant comprising aproppant wetted by an amount of water and/or a solids mixture comprisinga proppant and a dry friction reducer (DFR); a sprayer operable to sprayan aqueous liquid concentrate comprising a hydratable polymer onto theproppant from the proppant hopper, to spray water onto the solidsmixture from the proppant hopper, or to spray DFR onto the wettedproppant from the proppant hopper to provide a wetted solids mixture; anauger connected with the proppant hopper and with a slurry blender andoperable to mix the wetted solids mixture via screw action of the augerto provide a coated proppant, and introduce the coated proppant into theslurry blender, wherein the coated proppant comprises at least a partialcoating of the DFR and/or the hydratable polymer on the proppant; theslurry blender, wherein the slurry blender is downstream from theproppant hopper and configured to blend the coated proppant and anaqueous based fluid to provide a treatment fluid; fracturing equipmentdownstream from the slurry blender, and operable to inject the treatmentfluid into a wellbore, wherein the at least the partial coating of theDFR and/or the hydratable polymer of the coated proppant hydrates in theslurry blender, thus swelling to provide a swelled coating thatmitigates a striking impact of the proppant on the fracturing equipmentduring the fracturing treatment.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: conveying a plurality of proppant particulates into a blender at a job site; while conveying the plurality of proppant particulates into the blender, contacting a plurality of proppant particulates with an aqueous liquid concentrate comprising a hydratable polymer to at least partially coat one or more of the proppant particulates with the hydratable polymer, thereby forming coated proppant particulates; blending the plurality of proppant particulates comprising the coated proppant particulates with an aqueous base fluid in the blender to form a treatment fluid, the treatment fluid having a viscosity of about 25 cP or less; and introducing the treatment fluid from the blender into at least a portion of a subterranean formation that includes at least one fracture.
 2. The method of claim 1 wherein the treatment fluid is introduced into a well bore at the job site that penetrates at least a portion of the subterranean formation.
 3. The method of claim 1 wherein the treatment fluid is introduced into at least a portion of the subterranean formation using one or more pumps.
 4. The method of claim 1 further comprising, after the step of introducing the treatment fluid into at least a portion of the subterranean formation: allowing at least a portion of the hydratable polymer on the coated proppant particulates to detach from the proppant particulates and disperse into the treatment fluid.
 5. The method of claim 1 further comprising depositing at least a portion of the plurality of proppant particulates in the at least one fracture.
 6. The method of claim 1 wherein the viscosity of the treatment fluid is less than about 10 cP.
 7. The method of claim 1 wherein the viscosity of the treatment fluid is from about 3 cP to about 5 cP.
 8. The method of claim 1 further comprising: while conveying the plurality of proppant particulates into the blender, contacting the plurality of proppant particulates with a functionalizing agent before the step of contacting the plurality of proppant particulates with the aqueous liquid concentrate comprising the hydratable polymer.
 9. The method of claim 8 wherein the functionalizing agent comprises an organosilane.
 10. The method of claim 1 wherein the plurality of proppant particulate are conveyed into the blender using an auger, a sand screw, or both.
 11. The method of claim 1 wherein contacting the plurality of proppant particulates with the aqueous liquid concentrate comprising the hydratable polymer comprises spraying the aqueous liquid concentrate into the plurality of proppant particulates as the proppant particulates are dispensed from a storage container.
 12. The method of claim 1 further comprising blending a breaker additive with the aqueous base fluid and the plurality of proppant particulates in the blender to form the treatment fluid.
 13. The method of claim 1 wherein the hydratable polymer comprises at least two monomeric units selected from the group consisting of: acrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylic acid, an acrylic acid ester, a methacrylic acid ester, and any combination thereof.
 14. A method comprising: introducing an aqueous fracturing fluid into a well bore penetrating at least a portion of a subterranean formation at or above a pressure sufficient to create or enhance at least one fracture in the subterranean formation, the aqueous fracturing fluid having a viscosity of about 25 cP or less; conveying a plurality of proppant particulates from a storage container into a blender at a job site where the well bore is located; while conveying the plurality of proppant particulates into the blender, contacting the plurality of proppant particulates with an aqueous liquid concentrate comprising a hydratable polymer to at least partially coat a portion of the proppant particulates with the hydratable polymer, thereby forming coated proppant particulates; blending the plurality of proppant particulates comprising the coated proppant particulates with an aqueous base fluid in the blender to form a treatment fluid, the treatment fluid having a viscosity of about 25 cP or less; and introducing the treatment fluid from the blender into the well bore.
 15. The method of claim 14 further comprising, after the step of introducing the treatment fluid into the well bore: allowing at least a portion of them the hydratable polymer on the coated proppant particulates to detach from the proppant particulates and disperse into the treatment fluid.
 16. The method of claim 14 further comprising depositing at least a portion of the plurality of proppant particulates in at least one fracture in the subterranean formation.
 17. The method of claim 14 wherein the plurality of proppant particulate are conveyed into the blender using an auger, a sand screw, or both.
 18. A method comprising: introducing an aqueous fracturing fluid into a well bore penetrating at least a portion of a subterranean formation at or above a pressure sufficient to create or enhance at least one fracture in the subterranean formation, the aqueous fracturing fluid having a viscosity of about 25 cP or less; using an auger, a sand screw, or a combination thereof to convey a plurality of proppant particulates from a storage container into a blender at a job site where the well bore is located; while conveying the plurality of proppant particulates into the blender, contacting the plurality of proppant particulates with a functionalizing agent, and contacting the plurality of proppant particulates with an aqueous liquid concentrate comprising a hydratable polymer to at least partially coat a portion of the proppant particulates with the hydratable polymer, thereby forming coated proppant particulates; blending the plurality of proppant particulates comprising the coated proppant particulates with an aqueous base fluid in the blender to form a treatment fluid, the treatment fluid having a viscosity of about 25 cP or less; and introducing the treatment fluid from the blender into the well bore.
 19. The method of claim 18 further comprising depositing at least a portion of the plurality of proppant particulates in the at least one fracture.
 20. The method of claim 18 further comprising blending a breaker additive with the aqueous base fluid and the plurality of proppant particulates in the blender to form the treatment fluid. 